The present invention relates to an apparatus and a method for selectively controlling fluid flow. In particular, the invention relates to an apparatus and method for use in downhole operations in the hydrocarbon production industry. The invention also relates to a progressive cavity pump comprising a fluid flow control apparatus.
During extraction of resources from beneath the surface of the earth and especially in the oil and gas exploration and production industry, it is often necessary to overcome a pressure differential (hydrostatic head) between a subterranean fluid reservoir and the surface. This can be achieved using a pump such as a progressive cavity pump (hereinafter a “PCP”).
FIG. 1 is a cut away side view of part of a typical prior art PCP 12. PCPs 12 typically comprise a helical steel rotor 16 and a rubber stator 14 having a double screw profile matching the helical rotor 16. The stator 14 is formed to allow rotation of the inserted rotator 16 therein and this arrangement results in a series of cavities 18 along the length of the PCP 12 between the rotor 16 and the stator 14. The stator 14 is usually encapsulated within a tubing section (not shown) that typically forms part of a tubing string running from the reservoir to the surface. The rotor 16 is typically connected to a rod string (not shown) having a smaller diameter than the tubing string where the rod string is admitted within the throughbore of the tubing string and positioned such that the rotor 16 is located within the stator 14. The rod string is then connected to a rotary motor at the surface to power rotation of the rod string and attached rotor 16 at the appropriate speed.
When the PCP 12 is in use, rotation of the rotor 16 within the stator 14 creates a positive displacement that causes fluids in the cavities 18 to progress upwards due to a gradual build-up of pressure from the inlet to the discharge of the PCP 12. The build-up of pressure causes positive displacement of fluid within the cavities 18 and provides the necessary lift to extract fluid from the reservoir and pump it towards the surface thereby overcoming the hydrostatic head.
PCPs 12 are often used in wells that produce high quantities of sand along with the produced fluids due to the material selection of the pump 12 and use of the rubber stator 14 against the steel rotor 16, PCPs 12 are also suitable for production of heavy hydrocarbons and are commonly used in wells for extraction of high viscosity fluids. An important factor in determining the lifetime of the PCPs 12 is the quantity of sand and solids present in the hydrocarbon and fluid mixture passing through the pump 12.
Stopping operation of the PCP 12 can result in the sand (that is entrained in fluids within the production tubing above the PCP 12 having already been pumped) settling above the stator 14 and creating a sand plug in the tubing string. Once the PCP 12 is restarted, the rotor 16 may run dry within the stator 14 for a period of time until the requisite pressure accumulates to blast away the sand plug. During this period, the PCP 12 rotor 16 running dry within the stator 14 can tear up or otherwise cause severe damage to the stator 14 resulting in destruction of the pump 12. The PCP system would then require replacement with the associated high cost due to lengthy down time and loss of well production. Conventionally, this situation is avoided by dissipating the sand plug using a rig to pull the rod string and attached rotor 16 out of the stator 14. Sand can then fall through the stator 14 and out of the lower end of the pump 12 after which the rod string and attached rotor 16 can be repositioned within the stator 14. However, this operation is both costly and time consuming and results in undesirable downtime.
Since the PCP 12 is a positive displacement pump, there is no method for allowing fluids to free flow through the pump 12 from the reservoir to the surface in the event of pump 12 failure. Additionally, there is no method by which fluids from the surface can be forced into the reservoir through the pump 12 to conduct reservoir treatments. These operations are conventionally conducted by pulling the rod string and attached rotor 16 from the wellbore and allowing fluids to free flow through the stator 14. Again, this is a costly and time consuming operation and results in undesirable downtime.